For a variety of applications, fluids are injected into the earth, such as for hydraulic fracture stimulation, waste injection, produced water re-injection, or for enhanced oil recovery processes like water flooding, steam flooding, or CO2 flooding. In other applications, fluids are produced, i.e. removed, from the earth, such as for oil and gas production, geothermal steam production, or for waste clean-up.
Hydraulic fracturing is a worldwide multi-billion dollar industry, and is often used to increase the production of oil or gas from a well. The subsurface injection of pressurized fluid results in a deformation to the subsurface strata. This deformation may be in the form of a large planar parting of the rock, in the case of hydraulic fracture stimulation, or other processes where injection is above formation parting pressure. The resultant deformation may also be more complex, such as in cases where no fracturing is occurring, wherein the subsurface strata (rock layers) compact or swell, due to the poroelastic effects from altering the fluid pressure within the various rock layers.
The preparation of a new well for hydraulic fracturing typically comprises the steps of drilling a well, cementing a casing into the well to seal the well from the rock, and creating perforations at a desired target interval. Perforations are small holes through the casing, which are formed with an explosive device. The target interval is the desired depth within the well, which typically is at the level of a pay zone of oil and/or gas. A bridge plug is then inserted below the perforated interval, to seal off the lower region of the well.
Hydraulic fracturing within a prepared wellbore comprises the pumping of fluid, under high pressure, down the well. The only place that the fluid can escape is through the formed perforations, and into the target zone. The pressure created by the fluid is greater than the in situ stress on the rock, so fractures (cracks, fissures) are created. Proppant (usually sand) is then pumped into the prepared well, so that when the fluid leaks off into the rock (via natural porosity), the proppant creates a conductive path for the oil/gas to flow into the well bore. Creation of a hydraulic fracture, therefore, involves parting of the rock, and displacing the fracture faces, to create fracture width. As a result of hydraulic fracturing, the induced deformation field radiates in all directions.
Surface and offset well tiltmeter fracture mapping has been used to estimate and model the geometry of formed hydraulic fractures, by measuring fracture-induced rock deformation.
Surface tilt mapping typically requires a large number of tiltmeters, each located in a near-surface offset bore, which surround an active treatment well that is to be mapped. For example, surface tilt mapping installations often comprise approximately 12 to 30 surface tiltmeters. Tilt data collected from the array of tiltmeters from hydraulic fracturing is then used to estimate the direction, i.e. the orientation, of a fracture which is created in the active well.
G. Holzhausen, Analysis of Earth Tilts Resulting from Formation of Six Hydraulic Fractures, Crack'r Frac, Mar. 27–28, 1979, describes early development in tilt data analysis.
M. Wood, Method of Determining Change in Subsurface Structure due to Application of Fluid Pressure to the Earth, U.S. Pat. No. 4,271,696, issued 09 Jun. 1981, describes “a method of determination of the change in subsurface structure of the earth resulting from the application of fluid pressure at a selected point, at a selected depth, in the earth, by measuring at least one physical parameter of the contour of the subsurface of the earth above the point of application of fluid pressure. The method involves positioning a plurality of tiltmeters on the earth above the point of application of fluid pressure arranged in a known array, and measuring the change in angle of tilt of the earth's surface at the point of placement of each sensor while varying the pressure and flow rate of fluid into the earth at the selected point.”
M. Wood, Method of Determining the Azimuth and Length of a Deep Vertical Fracture in the Earth, U.S. Pat. No. 4,353,244, issued 12, Oct. 1982, describes “a method of determination of the change in subsurface structure of the earth resulting from the application of fluid pressure at a selected point, at a selected depth, in the earth, by measuring at least one physical parameter of the contour of the surface of the earth above the point of application of fluid pressure. The method involves positioning a plurality of tiltmeters on the earth above the point of application of fluid pressure arranged in a known array, and measuring the change in angle of tilt of the earth's surface at the point of placement of each sensor while varying the pressure and flow rate of fluid into the earth at the selected point. This invention further teaches how the individual values of incremental tilt at selected points on the earth's surface can be processed to provide indication of the azimuth of the vertical fracture in the earth, and an estimate of length of the fracture.”
However, in addition to the direction of a fracture, other details of the formed fracture are important, such as the length and the height of the fracture region. Surface measurements do not accurately reflect the magnitude and dimensions of a formed fracture, due primarily to the relative isolation of the surface tiltmeters from the fracture area. For example, surface tiltemeters are typically installed within ten to fifty feet of the surface, whereas fractures are commonly formed much deeper into the strata.
Recently, downhole offset tilt mapping has been developed, comprising an array of tiltmeters located in a well which is offset from the active treatment well. Offset tiltmeter arrays often comprise a string of seven to thirteen tiltmeters. The plurality of offset tiltmeters are usually located at depths which are comparable to the fracture region, e.g. such as within the fracture zone, as well as above and/or below the fracture zone. For example, for a fracture at a depth of 5,000 feet, with an estimated fracture height of 300 feet, and array having a plurality of offset tiltmeters, having a span larger than 300 feet, e.g. such as an 800 foot string array, may be located in an offset hole near the active well. The use of a larger number of offset tiltmeters, located above, within, and below a fracture zone, which aids in estimating the extent of the formed fracture zone.
The distance between an active well and an offset well in which an array of offset tiltmeters is located is often dependent on the location of existing wells, and the permeability of the local strata. For example, in existing oil well fields in many locations in California, the surrounding strata has low fluid mobility, which requires that wells are often located relatively close together, e.g. such as a 200 ft. spacing. In contrast to closely spaced wells in California, for gas well fields in many locations in Texas, the surrounding strata has higher fluid mobility, which allows gas wells to be located relatively far apart, e.g. such as a 1,000–5,000 ft. spacing.
P. Davis, Surface Deformation Associated with a Dipping Hydrofracture, Journal of Geophysical Research, Vol. 88, No. B7, Pages 5826–5834, 10, Jul. 1983, describes the modeling of crustal deformations associated with hydrofractures.
C. Wright, Tiltmeter Fracture Mapping: From the Surface, and Now Downhole, Hart's Petroleum International, January 1998, describes the use of surface and downhole offset tiltmeters for fracture mapping.
C. Wright, E. Davis, W. Minner, J. Ward, L. Weijers, E. Schell, and S. Hunter, Surface Tiltmeter Fracture Mapping reaches New Depths—10,000 Feet, and Beyond?, SPE 39919, Society of Petroleum Engineers Rocky Mountain Regional Conference, May 1998, Denver, Colo., describe surface tilt measurement and mapping techniques for resolution of fracture induced tilts.
C. Wright, E. Davis, G. Golich, J. Ward, S. Demetrius, W. Minner, and L. Weijers, Downhole Tiltmeter Fracture: Finally Measuring Hydraulic Fracture Dimensions, SPE 46194, Society of Petroleum Engineers Western Regional Conference, May 10–13, 1998, Bakersfield, Calif., describe downhole tiltmeter fracture mapping for offset wells.
P. Perri, M. Emanuele, W. Fong, M. Morea, Lost Hills CO2 Pilot: Evaluation, Injectivity Test Results, and Implementation, SPE 62526, Society of Petroleum Engineers Western Regional Conference, Jun. 19–23, 2000, Long Beach, Calif., describe the evaluation, design, and implementation of a CO2 pilot project and mapping of CO2 migration.
E. Davis, C. Wright, S. Demetrius, J. Choi, and G. Craley, Precise Tiltmeter Subsidence Monitoring Enhances Reservoir Management, SPE 62577, Society of Petroleum Engineers Western Regional Conference, Jun. 19–23, 2000, Long Beach, Calif., describe tiltmeter-based long term reservoir compaction and dilation due to fluid withdrawal and injection.
L. Griffin, C. Wright, E. Davis, S. Wolhart, and Z. Moschovidis, Surface and Downhole Tiltmeter Mapping: An effective Tool for Monitoring Downhole Drill Cuttings Disposal, SPE 63032, 2000 Society of Petroleum Engineers Annual Technical Conference, Oct. 1–4 2000, Dallas Tex., describe the use of both surface tiltmeters and offset downhole tiltmeters for drill cuttings disposal monitoring applications.
N. Warpinski, T. Steinfort, P. Branigan, and R. Wilmer, Apparatus and Method for Monitoring Underground Fracturing, U.S. Pat. No. 5,934,373, Issued 10, Aug. 1999, describe “an apparatus and method for measuring deformation of a rock mass around the vicinity of a fracture, commonly induced by hydraulic fracturing is provided. To this end, a well is drilled offset from the proposed fracture region, if no existing well is present. Once the well is formed to a depth approximately equal or exceeding the depth of the proposed fracture, a plurality of inclinometers, for example tiltmeters, are inserted downhole in the well. The inclinometers are located both above and below the approximate depth of the proposed fracture. The plurality of inclinometers may be arranged on a wireline that may be retrieved from the downhole portion of the well and used again or, alternatively, the inclinometers may be cemented in place. In either event, the inclinometers are used to measure the deformation of the rock around the induced fracture.”
The disclosed prior art systems and methodologies thus provide tiltmeter assemblies and systems for surface and offset tilt mapping. However, the prior art systems and methodologies fail to provide tiltmeter assemblies and systems within active wells, nor do they provide structures which can be used in an active well environment.
C. Wright, E. Davis, J. Ward, L. Griffin, M. Fisher, L. Lehman, D. Fulton, and J. Podowski, Real-Time Fracture Mapping from the Live Treatment Well, Abstract No. SPE71648, submitted December 2000 to Society of Petroleum Engineers for Annual Technical Conference, Sep. 30–Oct. 3, 2001, describes early development in hydraulic fracture mapping from within a treatment well.
It would be advantageous to provide a system for mapping an active wellbore which does not require either an offset wellbore or the installation of surface tilt arrays. It would be advantageous to construct a measurement device that could be placed into and survive within in an active treatment well, particularly during the pumping of a hydraulic fracture treatment. Furthermore, it would be advantageous to provide a tiltmeter in which induced motion of the subsurface strata is discernable from the induced motion from active fluid flow in the borehole. It would also be advantageous to provide a system for mapping an active wellbore which operates in a wider range of environments and provides a high resolution of fracture width and/or rock deformation pattern data across the subsurface rock strata. Furthermore, it would be advantageous to provide a system for mapping an active wellbore which can be deployed and survive in the hostile treatment well environment.